This edition of API MPMS Chapter 20.3 also supersedes the below listed sections of API Recommended Practice 85, Use of Subsea Wet-gas Flowmeters in Allocation Measurement Systems, First
Terms and Definitions
This document defines specific terms and concepts, with many definitions sourced from ISO/IEC Guide 98-3:2008 [15], unless stated otherwise.
2.1.1 actual conditions measurement conditions line conditions flowing conditions
Conditions of pressure and temperature of the fluid at the point where fluid properties or flows are measured.
The mathematical process involves calculating the proportion of produced fluids from specific entities—such as zones, wells, fields, leases, or producing units—relative to the total production of the entire system, which includes the reservoir, production system, and gathering systems This analysis is essential for determining the value or ownership attributed to each entity.
Measurement systems and procedures required to perform a fair and equitable allocation.
NOTE Such systems and procedures may not meet full custody transfer standards of measurement while still being sufficient for allocation purposes.
A device used to measure the flow rates from a single well or input flow line for the purpose of allocation (2.1.2), not to be confused with the reference meter (2.1.28).
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The three step process of:
1) verifying the accuracy of an instrument at various points over its operating range, possibly in both the ascending and descending direction, [see the definition of verification (2.1.34)];
2) adjusting the instrument, if it exceeds a specified tolerance, to conform to a measurement or reference standard;
3) reverification, if adjustments were made, thus providing accurate values over the instrument’s prescribed operating range.
To combine the hydrocarbon streams from two or more wells, units, leases, production zones, or production facilities into common vessels or pipelines.
Fluid separation in production streams can be achieved using compact equipment that is significantly smaller than traditional gravity-based separators, allowing for either complete or partial separation of fluids.
Of or relating to financial matters With respect to measurement, those that have a financial impact on custody transfer, allocation, royalty, or taxation.
Measurement systems and procedures are essential for accurately determining quantities that can directly affect the financial interests of involved parties This process is distinct from custody transfer measurement, as outlined in the API Manual.
Petroleum Measurement Standards [MPMS] Ch 1, Second Edition [9] ).
Multiphase flow in a conduit is characterized by the spatial and temporal distribution of its individual components, such as oil, gas, water, and injected chemicals An example of this is when liquid accumulates at the bottom of a horizontal conduit while the gas phase flows above it.
In three-phase production streams, achieving full separation of fluids ensures that the resulting streams are single-phase, meaning there are no liquids present in the gas stream, no gas in the liquid stream, and no commingling of oil and water This process differs from compact separation and partial separation methods.
The gas volume flow rate to total liquid volume flow rate ratio, measured under standard conditions, is typically expressed in standard cubic feet per barrel (scf/bbl) or standard cubic meters of gas per cubic meter of total liquid (m³/m³).
The gas volume flow rate to liquid hydrocarbon volume flow rate ratio, measured under standard conditions, is typically expressed in standard cubic feet per barrel (scf/bbl) or standard cubic meters of gas per cubic meter of liquid hydrocarbon (m³/m³).
The volume expansion factor quantifies the change in volume when one mole of gas is transitioned from actual pressure and temperature conditions to standard conditions This ratio illustrates how the gas's volume is expected to expand under standard conditions compared to its volume in situ.
The fraction of the total volumetric flow rate at actual conditions (2.1.1) in the pipe that is attributable to gas flow, often expressed as a percentage
The local cross-sectional area occupied by a specific phase in a multiphase flow is measured in relation to the total cross-sectional area of the conduit at the same location under actual conditions.
The fraction of the total volumetric flow rate at actual conditions (2.1.1) in the pipe that is attributable to liquid flow, often expressed as a percentage.
A dimensionless parameter (usually shown in equations as X) used to indicate the degree of “wetness” of a wet gas at actual conditions, defined as:
Flow of a composite fluid that includes natural gas, hydrocarbon liquids, water, and injected fluids, or any combination of these.
Multiphase flow in which the water and any other liquids present are distributed as droplets surrounded by liquid hydrocarbons (oil) in the liquid phase.
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The ratio of an oil volume at stock tank or other intermediate conditions to the volume of that same oil at actual metering conditions.
A description of the expected performance of a multiphase flow meter in liquid and gas flow rates, gas volume fraction (2.1.15), and water-liquid ratio (2.1.38).
NOTE It is often plotted on the flow and composition maps as measurement uncertainty contours.
The separation of production fluids resulting in streams likely to be multiphase, i.e wet gas and gassy liquid streams. See compact separation (2.1.7) and full separation (2.1.11).
The term refers to a specific component within a mixture, particularly highlighting elements such as oil, gas, water, or any other constituent present in various combinations.
The mass flow rate of one of the phases of a multiphase flow, relative to the total multiphase mass flow rate.
The volume flow rate of one of the phases of a multiphase flow at actual conditions, relative to the total multiphase volume flow rate, e.g gas volume fraction (2.1.15).
2.1.27 pressure-volume-temperature (PVT) relationship
Application of equations of state (EOS) to a composite fluid to calculate the change in properties in going from one set of conditions (P and T) to another
A flow meter is specifically designed to measure the flow rate of a single phase within a commingled stream, such as the flow rate of liquid hydrocarbons In some cases, reference meters are utilized to assess multiple phases, allowing for the measurement of total liquid flow and water cut to accurately determine both oil and water rates.
Conditions that exists when the phases have different velocities at a cross section of a conduit
A means of quantitatively expressing slip as the phase velocity ratio between the phases.
The phase velocity difference between two phases.
2.1.32 solution gas factor gas solubility factor
The amount of gas released from solution of a given volume of oil in going from actual metering conditions to standard conditions
NOTE Also called gas solubility factor, this can be expressed, for example, in standard cubic feet per barrel (scf/bbl) or cubic meter per cubic meter (m 3 /m 3 ).
The flow velocity of a single phase in a multiphase flow can be defined as the phase's volume flow rate divided by the cross-sectional area of the pipe This definition assumes that the phase completely occupies the conduit.
The process of confirming the accuracy of a meter or instrument.
2.1.35 void fraction gas hold-up gas void fraction
The cross-sectional area locally occupied by the gas phase of a multiphase flow, relative to the cross-sectional area of the conduit at the same local position.
The water volume flow rate, relative to the total liquid volume flow rate (oil and water), both converted to volumes at standard pressure and temperature
NOTE The WC is normally expressed as a percentage.
Multiphase flow in which the oil and other liquids present are distributed as droplets surrounded by water in the liquid phase.
The water volume flow rate, relative to the total liquid volume flow rate (oil and water), at the actual conditions (operating pressure and temperature), expressed as a percentage.
The trajectory of production parameters displayed by a well over time, sometimes shown in a flow or composition map (e.g see 3.3 and 3.6).
Expected production performance in a well is typically represented as uncertainty contours on flow and composition maps This region surrounding the well trajectory reflects the uncertainty associated with production estimates.
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A subset of multiphase flow in which the dominant fluid is gas and in which there is a presence of some liquid.
Abbreviations and Symbols
For the purposes of this document, the following abbreviations and symbols apply.
A Pipe pipe fractional cross-sectional area occupied by i th phase, gas or liquid
A Gas cross-sectional area of pipe occupied by gas flow
A Liquid cross-sectional area of pipe occupied by liquid flow α i liquid or gas volume fraction
GUM ISO Guide to uncertainty in measurement [20]
I system imbalance λGas gas hold-up λLiquid liquid hold-up
NFOGM Norwegian Society for Oil and Gas Measurement
P, T pressure and temperature at actual conditions
PLET pipeline end termination psi pounds per square inch
PVT pressure-volume-temperature mean value of a random variable q
Q o liquid hydrocarbon (oil) mass flow rate
Q o v liquid hydrocarbon (oil) volume flow rate
Q w v water volume flow rate ρ g gas density ρ l liquid density q
V velocity of liquid or gas in a pipe
V s,Gas superficial velocity of gas phase of a multiphase flow in pipe
V s,Liquid superficial velocity of liquid phase of a multiphase flow in pipe
3 Multiphase and Wet Gas Flow
General
Multiphase flow is a complex phenomenon that poses challenges in understanding, predicting, and modeling Traditional single-phase characteristics, including velocity profiles, turbulence, and boundary layers, are often inadequate for accurately describing these flows.
To grasp the nature of multiphase flow, it is essential to understand multiphase flow regimes, which describe the intricate interactions between different phases These regimes particularly highlight how liquid and gas phases move through pipes.
Multiphase Flow Regimes—Overview
Liquid-gas flow structures are categorized into distinct regimes, with their characteristics influenced by various parameters The spatial and temporal distribution of fluid phases varies across these flow regimes and is typically beyond the control of designers or operators.
Flow regimes are influenced by various factors, including operating conditions, fluid properties, flow rates, and the pipe's orientation and geometry The transition between these regimes occurs gradually, making it challenging to identify flow regimes in operational settings Additionally, the description of these regimes can be somewhat arbitrary, as it largely relies on the observer's interpretation.
The main mechanisms involved in forming the different flow regimes are: a) transient effects, b) geometry or terrain effects, c) hydrodynamic effects, and d) a combination of these
Transients arise from changes in system conditions, distinct from the unsteadiness of intermittent flow, with valve operations being a common cause Changes in pipeline geometry and terrain, excluding pipe cross-sectional area, can significantly impact flow, especially in subsea pipelines, where certain flow regimes, like severe riser slugging, can extend for kilometers In the absence of these transient and geometry/terrain effects, the steady-state flow regime is solely influenced by hydrodynamic factors such as flow rates, fluid properties, and pipe diameter.
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Flow regimes can be categorized into dispersed flow, separated flow, intermittent flow, or a combination of these types Dispersed flow occurs when small amounts of one phase are mixed within a dominant phase, exemplified by bubble and mist flow Separated flow is marked by a noncontinuous phase distribution radially and a continuous distribution axially, with stratified and annular flows as key examples Intermittent flow is characterized by noncontinuous behavior in the axial direction, leading to locally unsteady conditions, as seen in elongated bubble, churn, and slug flow These flow regimes represent various hydrodynamic two-phase gas-liquid interactions.
The flow illustrated in Figure 1 highlights a crucial aspect discussed in Section 4 regarding metering techniques It demonstrates that the flow regimes are essentially two distinct regimes operating in series Meters designed to function at average gas volume fraction (GVF), water-liquid ratio (WLR), and long-term flow rates will be ineffective; thus, they must perform efficiently in both gas-dominant and liquid-dominant conditions This adaptability is a fundamental trait of effective multiphase flow metering systems.
Liquid-liquid interactions typically have a less significant impact on flow regimes compared to liquid-gas interactions, allowing the liquid-liquid portion to be viewed as a dispersed flow Nonetheless, the characteristics of the liquid-liquid mixture are influenced by the volumetric ratio of the two liquid components.
Figure 1—Multiphase Flow Regime Concepts
Multiphase Flow Regimes—Graphical Representation
Figures 6 and 7 illustrate the most common flow regimes and their locations within the two-phase gas-liquid flow map, which aids in understanding multiphase flow dynamics While physical parameters like gas and liquid density, viscosity, and surface tension influence actual flow regimes, they are not represented in this presentation, meaning the true regime locations and boundaries may vary A critical factor is the diameter of the flow line; for instance, reducing the flow line size from 4 inches to 3 inches, while maintaining constant liquid and gas flow rates, results in an increase in both superficial gas and liquid velocities by a factor of 16/9 Consequently, this adjustment shifts the point along the diagonal of the two-phase flow map, potentially altering the flow regime, such as transitioning from stratified flow.
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`,,```,,,,````-`-`,,`,,`,`,,` - slug flow, or from slug flow to annular Multiphase flow regimes also have no sharp boundaries, but rather change smoothly from one regime to another.
Most oil wells experience multiphase flow within their pipework Despite the pressure at the well's bottom often surpassing the oil's bubble point, the gradual pressure drop during the ascent of oil to the surface results in an increasing release of gas from the oil Figures 5 and 6 qualitatively illustrate how the transitions in flow regime are influenced by the superficial gas and liquid velocities in both vertical and horizontal multiphase flow.
Superficial velocity is a key concept in flow regime maps, defined as the gas velocity assuming no liquid is present in the pipe It is calculated by dividing the volumetric total gas throughput at operating conditions by the total cross-sectional area of the pipe Similarly, superficial liquid velocity can be derived using analogous principles The fractional areas occupied by gas and liquid in the pipe, along with their respective actual velocities at line pressure and temperature, are essential for these calculations.
Gas hold-up/void fraction:
In two-phase flow within a pipe, the liquid fraction of the cross-sectional area increases due to the slip effect between the gas and liquid phases Typically, the lighter gas moves faster than the heavier liquid, which tends to accumulate in horizontal and inclined sections of the pipe The liquid hold-up and gas void fraction, defined under two-phase flow conditions, represent the liquid and gas fractions of the pipe's cross-sectional area Notably, the liquid hold-up exceeds the liquid volume fraction (LVF) due to slip, with equality occurring only when there is no slip and both phases travel at the same velocity These concepts are further illustrated in Figure 5.
Note that with the liquid hold-up and the actual velocities, the superficial gas and liquid velocities can be calculated. Also note that , always.
In addition to the two-phase liquid-gas flow maps presented in Figures 6 and 7, which depict vertical and horizontal flow regimes, a composition map serves as another valuable graphical tool This map aids in comprehending the components of the multiphase mixture and will be further explored in this section and in Section 6, which focuses on uncertainty.
Figure 5—Gas Void Fraction, Gas Volume Fraction, and Slip
Figure 6—A Generic Two-phase Vertical Flow Map, Log-log Scale
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The two-phase flow map in Figure 6 illustrates the typical positions of various vertical flow regimes It is important to note that when the superficial gas velocity exceeds a certain threshold, the multiphase flow transitions to an annular regime regardless of the superficial liquid velocities.
Vertical flow regimes tend to achieve axial symmetry, meaning that liquid and gas phases do not naturally separate in any specific azimuthal direction This contrasts with horizontal flow regimes, where gravity causes heavier liquids to settle at the bottom of the pipe Consequently, vertical installation is often favored for most multiphase flow meters (MPFMs) to simplify the variety of flow regimes encountered.
In horizontal multiphase flow, the transition between different flow regimes is influenced by factors such as pipe diameter, interfacial tension, and phase densities Figure 7 qualitatively illustrates the relationship between superficial gas and liquid velocities and the resulting flow regime transitions.
A map such this is only valid for a specific pipe, pressure, and multiphase fluid.
In horizontal flow regimes, unlike vertical ones, the flow is typically not axially symmetric due to the influence of gravity This results in heavier liquids settling at the bottom of the pipe, while the lighter gas phase moves along the top.
Composition and Fluid Properties
Understanding multiphase flow in closed pipes requires not only characterizing the flow rates of liquids and gases but also identifying their constituents and physical properties This involves determining the relative fractional proportions of each phase present at any given point in the pipe, known as phase fractions.
Figure 7—A Generic Two-phase Horizontal Flow Map, Log-log Scale
Coupled with the knowledge of phase velocities discussed in 3.3, this identifies the flow in terms of its phase rates at actual conditions (at line pressure).
Understanding the nature and properties of fluids flowing through a meter is crucial for optimal meter performance The most effective way to assess these properties for a specific well at a particular moment is through fluid sampling.
To ensure the accuracy of fluid meters, it is essential to identify the types of fluid sampling needed, the estimated sampling frequency, and the information to be obtained from the samples This process typically relies on the sensitivity of the selected meter to changes in fluid properties, as provided by the meter vendor The sampling frequency should be determined based on the meter's sensitivity coefficients and the rate at which fluid properties change after production commences.
However, there is a great deal more that is needed to fully identify the flow from the perspective of composition The most important of these will be discussed herein.
The liquid hydrocarbons most commonly encountered fall into three general categories as detailed in the following pieces and the properties of which are shown in Table 1.
Gas condensate, commonly referred to as condensate, is a blend of low-density hydrocarbon liquids that forms when a natural gas stream is cooled below its hydrocarbon dew point.
Condensates can pose significant measurement challenges, especially when they are the main liquid component in wet gas systems These gas-dominant systems often complicate the accurate estimation of liquid rates and composition compared to liquid-dominant systems.
For more on the properties of gas condensates, the reader is referred to GPA Standard 2145 [14] on the subject.
3.4.2.3 Black Oil, Light Crude Oil
This hydrocarbon liquid designation applies to those crude oils with properties that range between those of gas condensate and heavy oil
In multiphase flow streams dominated by hydrocarbon liquids, measuring both composition and flow rate is typically more straightforward compared to gas condensate or heavy oil systems.
Table 1—Fluid Properties of Typical Produced Liquids at Standard Conditions
Relative Density Range API Gravity Range degrees Viscosity Range centipoise at 20°C
(dependent on salinity) Not applicable 1.0
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Heavy oil, characterized by high density with an API Gravity below 20° or a relative density exceeding 0.933, is known for its high viscosity This property complicates the production and transportation processes compared to lighter crude oils.
Measuring heavy oil systems presents challenges primarily due to low Reynolds numbers, which lead to laminar flow and highly variable discharge coefficients in differential meters Additionally, the formation of emulsions with produced water results in liquids that also exhibit high and variable viscosity, low Reynolds numbers, and inconsistent discharge coefficients For further insights, readers can refer to relevant studies on this topic.
Hydrocarbon gases are gaseous compounds that are extracted from reservoirs and transported through pipelines These gases are composed of hydrogen and carbon atoms arranged in various configurations, with the most prevalent molecules being methane (C1), ethane (C2), propane (C3), butane (C4), pentane (C5), and hexane (C6).
In addition to hydrocarbon gas molecules, certain non-hydrocarbon gases may be present Hydrogen sulfide (H 2 S), carbon dioxide (CO 2 ), and inert gases such as nitrogen (N 2 ) are among the most common.
Natural gas mixtures consist of hydrocarbon and non-hydrocarbon molecules, making it challenging to define their properties These properties vary based on the gas composition, pressure, and temperature Additionally, the mixture's composition influences flow rate measurements, particularly through the density factor.
For more information on the physical properties of natural gas components and mixtures, the interested reader is referred to GPA Standard 2145 [14] and AGA Report No 8/API MPMS Ch 14.2 [12]
Water can be produced through the meter from a number of sources, for example:
— water present as a liquid in the reservoir;
— water produced as a vapor with natural gas;
— water injected to enhance production, either as a liquid or steam.
A problem for measurement can occur when waters from two or more sources are combined, with the resulting properties mixed and possibly variable.
Water salinity significantly influences both the density and electrical conductivity of water, primarily due to dissolved salt ions The most prevalent salts found in produced water include sodium chloride (NaCl), calcium chloride (CaCl2), and potassium chloride (KCl), although other salts may also be present While electrical properties of fluids are typically utilized to assess water-to-liquid ratio (WLR), this method is not universally applicable to all measurement devices.
Watercut (WC) measurement is influenced by the salinity value utilized, and unknown variations in salinity can lead to unpredictable errors in Water Liquid Ratio (WLR) measurements Most multiphase and wet gas meters necessitate fluid samples for calibration or to adjust the meter according to specific salt properties The accuracy of these meters is largely dependent on the density or conductivity of water, meaning that any alterations in these parameters can result in measurement errors.
`,,```,,,,````-`-`,,`,,`,`,,` - estimated water fraction, or WLR, by the meter For this reason, anything that can be done to eliminate or minimize these effects is significant.
Steam has long been utilized to decrease the viscosity of in situ heavy oil An essential factor in steam operations is steam quality, which refers to the mass fraction of a steam-water mixture that consists of steam.
3.4.5 Other Materials Conveyed by the Meter
From time to time, materials other than produced hydrocarbons and water will be transported through the metering system, e.g sand In these instances, two issues should be considered:
1) the meter’s ability to detect their presence and perhaps measure them, in addition to distinguishing them from produced fluids; and
2) the harm to the short- or long-term health of the meter due to exposure to the materials e.g erosion.
In addition to the typical hydrocarbons and water produced from a reservoir, other liquids may also be present in the flow stream This article focuses on those liquids that are consistently part of the flow, such as various inhibitors, while excluding transient substances like drilling fluids that only appear briefly during the field's lifecycle.
Chemicals are frequently injected into the flow stream, typically upstream of the meter, to manage various operational challenges Commonly used substances include hydrate inhibitors such as methanol and monoethylene glycol (MEG), along with scale, corrosion, wax, and asphaltene inhibitors.
The use of diluents to dilute a heavy oil stream, reduce the oil viscosity, and thereby increase its ability to flow freely, is common practice.
Piping Aspects of Multiphase Flow
The presence of pipework near the meter significantly influences both the flow regime and the fluid composition within the pipes.
The main impact of commingled flow lies in the composition of the resulting multiphase mixture, making it challenging to discern the properties of the individual contributing streams For instance, variations in the relative proportions of two distinct sources can alter the physical properties of the commingled flow as recorded by the meter.
3.5.3 Installation Piping Effects—Orientation, Asymmetry, Swirl
In order to reduce the effects of asymmetry on the measurement, a vertical orientation is usually preferred This is consistent with 3.3 on importance of flow regimes.
The effects of upstream pipework, such as bends and pipe size changes, are generally ignored in multiphase flow measurement.
The measurement of multiphase flow often necessitates the mixing of its components beforehand While various advanced techniques have been utilized historically, the "blind tee" method remains a widely adopted approach.
Multiphase Operating Envelope (OE), Well Production Profile, and Trajectory
The operating envelope of a multiphase meter is crucial for understanding its performance in specific well applications It is essential for users to first establish the well's production profile, which predicts the range of flow rates and composition conditions throughout the well's lifetime By combining this production profile with the operating envelope, users can assess the compatibility between the meter and the well, and identify when the multiphase flow meter (MPFM) may require replacement or the addition of a smaller meter during the well's operational period.
Another concept related to the well’s envelope is its trajectory (2.1.39), the best estimate of the path the production profile will follow over its lifetime.
The most effective manner of demonstrating these concepts is through the use of graphical tools, namely flow and composition maps.
This section discusses a single well production profile, but it's important to note that many Multi-Phase Flow Meters (MPFMs) are used to measure flow from multiple wells The principles outlined here are also applicable to the production profiles of a group of wells or an entire field.
Multiphase meters are typically engineered for either liquid-dominant or gas-dominant flow If the production trajectory is expected to transition between these flow types over the field's lifespan, it is essential to consider the potential need for meter modification or replacement during that time.
3.6.2 Graphical Depiction on the Flow Map
Figure 8 depicts the production profile, operational envelope (OE), and well trajectory on a two-phase flow map The red lines illustrate the well's trajectory, while the surrounding uncertainty is represented by the production profile The green envelope indicates the meter's performance at ±5% and ±10% levels This comparison allows for the evaluation of a meter's suitability for specific applications throughout the well's lifespan.
The production profile and meter OEs depicted on the flow map are intended solely as illustrations of the graphical methodology and do not reflect actual expectations in a real field scenario.
3.6.3 Graphical Depiction on the Composition Map
Figure 9 depicts the production profile, operating envelope (OE), and trajectory on the composition map, which plots a well's production in relation to gas volume fraction (GVF) and water-to-liquid ratio (WLR) The red lines illustrate the well's trajectory, accompanied by uncertainty margins, while the green envelope represents the meter's WLR at different levels Additionally, the flow map displays GVF uncertainty By analyzing the production profile alongside the meter's OEs, one can evaluate the suitability of a meter for specific applications.
The production profile and meter envelope depicted on the composition map are merely illustrative examples of the graphical methodology and do not reflect actual expectations in a real field scenario.
Figure 8—Illustration of Concepts of Production Profile, Operating Envelope, and Well Trajectory on the Two-phase Flow Map
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Evaluating the alignment between the production profile and the operating envelope (OE) is essential for selecting multiphase meters To facilitate this process, many operators utilize tools, including a spreadsheet tool detailed in Annex A.
4 Techniques of Multiphase Flow Metering Systems
In-line Meters
In-line or full-bore multiphase flow meters (MPFMs) measure phase fractions and flow rates directly within the multiphase flow line, without any separation of the flow, whether partial or complete.
The volume flow rate of each phase can be represented by its area fraction multiplied by the velocity of each phase.
In a typical gas/water/oil application, six parameters are needed—three phase fractions and three phase velocities.
Various meters employ distinct techniques to measure or deduce the six unknown parameters essential for multiphase volume calculations Certain multiphase flow meters (MPFMs) necessitate that all phases move at a uniform velocity, which simplifies the measurement process to three fractions and a common velocity This uniformity is typically accomplished with the aid of additional devices like mixers or positive displacement (PD) meters.
Many of the top commercially available Multi-Phase Flow Meters (MPFMs) are in-line devices that utilize specific flow and composition measurement principles.
Most in-line meters can effectively operate with a partial separation system if the conditions are suitable and the user prefers this setup.
Figure 9—Illustration of Concepts of Production Profile, Operating Envelope, and Well Trajectory on the Composition Map
4.1.2.1 Gamma Ray Absorption by the Fluid
The use of low-energy gamma radiation is common in many fields, e.g medical imaging, nondestructive testing, security systems, etc It is a method of monitoring multiphase flow streams.
4.1.2.1.2 Single-energy Gamma Ray Densitometry
Single-energy gamma ray absorption is the most prevalent method for measuring fluid density in multiphase fluids, which is a crucial parameter utilized in most multiphase flow meters (MPFMs).
4.1.2.1.3 Multiple-energy Gamma Ray Spectroscopy
Utilizing a gamma ray source that emits multiple energy levels allows for the measurement of attenuation at these specific spectral lines This data can then be input into a multiphase fluid model to determine the relative proportions of oil, water, and gas present in the mixture.
Gamma ray spectroscopy is utilized for composition measurements, as illustrated in Figure 10 The relative attenuation of oil, gas, and water varies with the energy of gamma ray photons, allowing for the formulation of equations that connect the fluid composition (phase fractions) to the measured attenuation at different energies With sufficient counts to minimize statistical uncertainty, it is possible to estimate the three phase fractions accurately.
Several meters have been developed that use gamma ray spectroscopy for phase fraction estimation
Most materials used in MPFMs consist of radioactive isotopes that undergo continuous decay, resulting in a decrease in the available material to emit photons as the source ages Consequently, the activity level, or "strength," of these sources consistently declines The rate of this decay is typically measured by the half-life, which indicates the time required for the source to reduce to half its original strength.
Different meters utilize various sources based on the absorption characteristics of fluids at specific wavelengths It is crucial for users of Multi-Phase Flow Meters (MPFMs) to understand the sources employed in their selected meters This knowledge is essential not only for safety considerations but also for recognizing the decay in source strength over time.
Figure 10—Low-energy Gamma Ray Absorption by Oil, Gas, and Water
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When the half-life of a source is significantly shorter than the operational period of a meter, the decrease in source counts must be integrated into the meter's algorithms Additionally, it may be essential to replace the source periodically to ensure optimal performance of the meter.
Measuring the transmission spectrum of near infrared (NIR) photons as they travel through fluid in a pipe allows for the estimation of the concentrations of energy-absorbing components This technique is especially effective in detecting water, even at minimal concentrations.
Measuring permittivity, also known as the relative dielectric constant, is essential for estimating the aqueous phases in multiphase streams Specifically, capacitance and microwave sensors are widely used to determine the water content (WC) or water fraction in oil-continuous and wet gas flows.
In multiphase flow scenarios where water is the predominant liquid phase, permittivity sensors may struggle with conductive mediums during measurements To address this challenge, some meters utilize inductive methods to assess fluid conductivity instead of estimating permittivity, as outlined in Section 7.2.2.2 of the NFOGM Handbook.
A differential meter can be used to obtain fluid density if the flow metering system has another means for estimation of flow velocity, such as cross correlation.
Coriolis measurement can reliably estimate the water cut (WC) of two-phase liquid in flow lines where gas is largely absent, utilizing density measurements under specific conditions.
Pressure and temperature are fundamental measurements essential for any meter They are not only necessary for the measurement process itself but also crucial for converting actual operating conditions to standard conditions.
Compact or Partial Separation
Separating a multiphase fluid stream into wet gas and gassy liquid streams allows for more effective measurement using two meters that operate optimally within specific regions of the multiphase map The effectiveness of this approach relies on the efficiency of the separation process and the performance of each meter on the partially separated streams A key advantage of this strategy is the use of a compact separator, which is significantly smaller than traditional gravity-based separators.
The concept of metering using partial separation is illustrated in Figure 11.
When using a single phase meter downstream of a partial separator without applying any correlation or correction, it is important for the user to recognize that there will be a measurement bias, which is directly related to the efficiency of the partial separation process.
This technique is described in several references to specific instruments.
Other Considerations
Noninvasive metering devices, such as clamp-on technologies, are utilized in multiphase flows and can be either acoustic or radioactive These devices can operate independently for specific phase rate measurements or be integrated with invasive components to create a comprehensive multiphase flow metering system.
An interpolative method connects sensor responses to known flow parameters like composition and rate on a large scale By analyzing sensor responses to various stimulus conditions, an algorithm is trained to interpolate results In multiphase metering systems, neural networks or other interpolative algorithms facilitate an in situ training process While neural networks excel at interpolation, they do not perform extrapolation.
4.3.3 Flow Modeling, Virtual Flow Meters, Nodal Analysis
Flow modeling involves techniques that utilize measurements, primarily pressure and temperature, to simulate multiphase flow This process enables the estimation of various flow parameters, including phase velocities, mass rates, and compositions.
Virtual flow metering (VFM) is a flow modeling technique that estimates oil, gas, and water flow rates by utilizing measurements like bottomhole and choke pressures, as well as temperatures.
Although these methods are attractive due to their simplicity, it is important to note that there are no established physical principles that can explicitly determine oil and water rates solely from pressure and temperature data, as the same pressure and temperature readings can arise from various combinations of oil and water.
Figure 11—Illustration of Multiphase Flow Measurement Using Partial Separation
Single-phase or wet gas flow meter
Single- or multi- phase flow meter
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`,,```,,,,````-`-`,,`,,`,`,,` - water rates Thus VFM flow rate estimates always depend on methods tied to compositional models of state, actual known rates from other project wells, user experience, and guesses.
Nodal analysis, a methodology established in the 1960s as part of VFM, is utilized to forecast production flow rates, pressures, and temperatures by measuring at various nodes along flow paths This system can include multiple wells, where measured parameters are modeled to estimate unknown values Enhanced accuracy in these estimates is achieved with greater pressure differences between nodes.
5 Multiphase Flow Metering Systems—Calibration, Correction, Performance Testing, and Verification
General
To accurately characterize multiphase flow meters (MPFMs), various tests are essential While some tests, such as the factory acceptance test (FAT), are mandatory for every meter produced, others, like high pressure/high temperature (HP/HT) testing, may only be necessary at the start of a meter's operational life.
The vendor typically supplies the necessary procedures for the routine operation of the meter, including any required special equipment or software, along with recommendations for the frequency of these procedures Additionally, for applicable sensors or devices, traceability to appropriate reference standards should be ensured.
Sensor Calibration
Calibration of an MPFM's components does not guarantee its overall accuracy It involves adjusting primary sensors, including pressure, differential pressure, or temperature, to rectify any drift in gain or offset.
An MPFM system depends on multiple sensors and transmitters, which significantly impact the accuracy of multiphase flow measurements Therefore, the precise calibration of each sensor and primary device is crucial for ensuring optimal performance of the MPFM.
Examples of these kinds of instruments are:
— pressure and temperature measurement devices;
— electrical properties sensors, such as capacitance, conductance, and microwave systems;
Regular calibration of sensors helps manage issues related to sensor drift However, it is important to note that proper calibration does not guarantee meter accuracy; it only ensures that the sensors operate within specified parameters at a given point or range.
Calibrating field sensors is often logistically challenging, leading to a lack of requirement for traceability Nonetheless, when calibration is feasible, it is essential that the process remains traceable.
Calibration frequency requirements vary significantly due to the diverse technologies and applications of meters, such as subsea, high pressure/high temperature (HP/HT), sour service, and unmanned platforms.
`,,```,,,,````-`-`,,`,,`,`,,` - subject that the user will normally discuss with the vendor in order to ensure that the meter is always producing results within the expected performance range.
Static Meter Correction
Meter readings obtained under no-flow conditions with fluids of known properties are essential for characterizing a Multi-Phase Flow Meter (MPFM) Examples of these measurements include readings from empty, water-filled, and oil-filled pipes By logging baseline parameters during factory calibration, field commissioning, and at regular intervals, trends can be established to differentiate between random measurement deviations and systematic drift.
A static meter correction is sometimes used to describe the activity of installing the device in a multiphase flow loop,recording the meter’s zero flow performance, and possibly adjusting certain parameters.
Operating Condition Testing
Operating condition testing for a Multi-Phase Flow Meter (MPFM) evaluates its performance against specifications related to pressure, temperature, and electromagnetic interference under anticipated operating conditions Similar to other instruments, third-party certification laboratories conduct qualification tests to ensure compliance with established standards.
Test/Verification in a Reference Facility
Flow loop testing of Multi-Phase Flow Meters (MPFMs) is essential for evaluating meter performance These tests effectively assess the functionality and reliability of the instruments, software, algorithms, and control systems involved in partial separation Conducted under controlled and quantifiable flow conditions, they provide valuable insights into the meter's operational capabilities.
A key consideration in the selection of a reference test facility is its suitability and ability to create relevant flow conditions for the intended application.
5.5.2 Requirements of Flow Test Facilities
When considering the evaluation of a meter's performance in its intended application environment, users must determine the usefulness of a multiphase flow reference facility It is essential for users to have a clear rationale for conducting flow loop testing and selecting an appropriate reference loop.
A multiphase reference flow facility, similar to those used for single-phase flow, routinely calibrates its sensors in a traceable manner to ensure accurate measurements of oil, gas, and water flow rates.
When conducting a flow loop test, it is essential to select fluid types that closely resemble those expected in real-world applications, such as heavy oil or gas condensate, ensuring they share similar properties like density and viscosity.
Meter flow loop verification frequently includes testing with "inert" fluids such as stabilized crudes, kerosene, and nitrogen This approach can more effectively assess the meter's fundamental flow dynamics and sensor responses compared to using "live" fluids, where there is a greater risk of significant phase changes.
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5.5.4 Meter Flow Rate Performance Tests
Before a test meter is put into service, users typically have an understanding of its performance Therefore, the primary goal of testing in a reference facility is to functionally verify that the meter meets the manufacturer's claimed performance specifications.
It is virtually impossible to duplicate the precise conditions that will be seen in the real application, so testing in a reference loop involves making appropriate, necessary compromises.
The test matrix is designed to encompass the expected range of flow conditions in the field, but it may be limited by the operational envelopes of both the test meter and the test facility An example of such a test matrix from a meter manufacturer is available in Annex C, which illustrates that 21 test points were chosen specifically for a 3-inch meter.
1) the main velocity element, a Venturi meter;
2) the meter response in multiphase flow over several GVF and WLR conditions; and
3) the meter response in wet gas.
Factory Acceptance Test (FAT)
Before shipping the MPFM from the factory, a Factory Acceptance Test (FAT) is typically conducted by the vendor and observed by the client or their representative This test aims to verify that the system operates effectively in all respects and is usually performed with the MPFM fully assembled It is important to note that a FAT does not always require process flow.
The Factory Acceptance Test (FAT) comprehensively evaluates all instrumentation functionalities, including necessary flow computers and communication with service computers, while thoroughly testing both software and hardware components.
— power-up test of the entire system;